As a wellbore is drilled into a subterranean formation, the formation near the wellbore is exposed to drilling fluid (“mud”) filtrate invasion. When such drilling operations utilize a water-based mud (“WBM”), for example, the invasion displaces oil in the vicinity of the wellbore because the mud filtrate and the oil in the formation are immiscible. A similar situation exists when oil-based mud (OBM) is utilized to form a wellbore in a formation containing non-oil formation fluids, such as water or a combination of water and gas.
However, existing in-situ formation fluid testing techniques often rely on algorithms that assume the mud and formation fluids are miscible, and may therefore provide inaccurate results with regard to the various parameters of the formation fluid being investigated. Alternatively, a core sample may be removed from the formation and transported away from the wellsite for laboratory testing that can account for the immiscible nature of the filtrate and formation fluids. However, several weeks or months may elapse before the lab results are available.